Oil and gas are produced from porous reservoirs by drilling wells into the formation, and using a pressure gradient to transport the hydrocarbons to the surface. This pressure gradient is normally achieved by means of pumps, which are required for situations where the reservoir pressure is not high enough to overcome the hydrostatic pressure between the reservoir depth and the surface.
Hydraulic fracturing is a term applied to a variety of techniques used to stimulate the production of oil, gas and other fluids from subterranean formations by means of increasing the permeability or conductivity thereof. In hydraulic fracturing, a suitable fracturing fluid is introduced into a subterranean formation through a wellbore under conditions of flow rate and pressure which are at least sufficient to cause the formation to break and to create and extend a fracture into the desired part of the formation. The fracturing fluid carries with it a proppant (e.g. sand, bauxite, etc.), transported into the fracture to create a high permeability path, and to prevent complete closure of the newly opened formation once the pressure gradient is reversed for production.
A fracturing fluid must be carefully designed to meet the rheological specifications imposed by its required performance. The fracturing fluid must have a sufficiently high viscosity to create and propagate the fracture through the rock, and to maintain the proppant in suspension as the fracturing fluid flows into the fracture. Very high viscosities are not advisable because an excessive pressure drop can be generated due to friction, which results in unacceptable horsepower pumping requirements. After the pressure is released and the formation has closed on to the newly placed proppant, the ideal fracturing fluid should revert to a low viscosity fluid which can be easily removed from the propped fracture to facilitate a high production rate.
In the early days of hydraulic fracturing, oil based fluids were formulated. Other oil containing fluids have been recently disclosed. Most fracturing fluids used nowadays are aqueous-based liquids, which have been either gelled or foamed. Examples of such viscosifying fluids are: i) viscoelastic surfactants (VES) ii) water soluble natural polymers; iii) water soluble or dispersible synthetic polymers; iv) polymer mixtures; and v) VES and polymer mixtures. A good review of the available technologies and additives commonly used in fracturing formulations can be found in Economides/Nolte (Eds.) “Reservoir Stimulation”, Third edition (2000), Chapter 7.
Viscoelastic surfactants form long worm-like micelles that entangle providing the fluid with the adequate rheological properties. Their viscosity is readily reduced by contact with oil or with organic solvents, and thus VES based fluids show a high degree of clean-up from the propped fracture.
Polymeric fracturing fluids form a “filter cake” at the wall of the fracture preventing the viscous fluid from excessive, water depletion. Most frequently, the polymeric gelling agent of choice is a water-soluble polysaccharide. These water-soluble polysaccharides form a known class of compounds that include a variety of natural gums as well as certain cellulosic derivatives that have been rendered hydratable by virtue of hydrophilic substituents chemically attached to the cellulose backbone. Such water-soluble polysaccharides are, amongst others, galactomannan gums; glucomannan gums, cellulose derivatives, xanthan gum and their chemically modified derivatives. Such water-soluble polysaccharides have a recognized capacity to thicken aqueous liquids. Particularly for low temperature wells, the thickened aqueous liquid has sufficient viscosity to carry the proppant during the fracturing process. In other instances, particularly at higher temperatures, it is necessary to cross-link the polysaccharide in order to form a gel having sufficient strength and viscosity to create a propped fracture. A number of cross-linkers have been developed to achieve the cross-linking, among which the most frequently used cross-linker species are borate, B(OH)4− and complexes of Ti(IV), Zr(IV) and Al(III).
One of the first polymers used to viscosify water for fracturing applications was guar gum, a long chain, high molecular weight galactomannan obtained from the endosperm of the ‘Cyamopsis Tetragonalobus’ plant, grown mainly in Pakistan and India and more recently in USA. Guar gum is a widely available, reasonably low priced raw material that requires little processing and therefore is one of the preferred options in the field. When required, guar gum can be cross-linked with Borate, Titanate, and Zirconate through the cis hydroxyl groups present on the mannose backbone of the polymer. Delayed cross-linkers, as well as polymer stabilizers or suspended water-insoluble, meltable or degradable polymers find common use in guar based fracturing fluid formulations. Methods to optimize the temperature stability of the fracturing fluids involving pH adjustment to maximize cationic charge density have also been disclosed.
A problem experienced when using gelled and cross-linked polysaccharide fracturing fluids is the breaking and clean-up of such fluids after the fracture has closed. The cross-linked polymer gel remaining in the propped fracture is often very difficult to remove and so is the filter cake. The breaking of such polymeric fracturing fluids has commonly been accomplished by adding a breaker component such as an encapsulated breaker that is released as the fracture closes.
U.S. Pat. No. 5,036,919 describes a method consisting of pumping two polymeric fracturing fluids differing in gel strength: a first fluid with a higher gel strength to form the filter cake and a second fluid more prone to degrade to generate the proppant pack. Breakers such as oxidizers, redox agents, enzymes and acid release agents that attack the acetal linkages in the polysaccharide polymer backbone have been used more or less successfully to improve fracture conductivity. Patent WO 01/34939 extensively discusses some of the different systems known in the field.
Several other breaker systems have been disclosed: breakers encapsulated in a surfactant at room temperature but soluble at formation temperature; delayed breaker pellets produced by combining a breaker with a hydratable gelling agent; breakers introduced within hollow or porous crushable glass, ceramics, plastics or gel beads; breakers coated by brittle polymers which release the breaker upon closure of the fracture; breakers that coordinate with the cross-linker ion, preventing its reaction with the polysaccharide; encapsulated breaker slurries, comprising a breaker enclosed within a coating, a high flash point solvent and a suspending agent; breakers encapsulated by a hydrolytically degradable polymer coating; breakers encapsulated in permeable enclosures to allow the migration of the breaker into the fracturing fluid; oil degradable encapsulated breaker particulates aiming to break hydrocarbon liquid gels; delayed breakers and combinations of delayed and non delayed breakers. Enzyme breakers disclosed in the literature are: hydrolase enzyme breakers pumped together with the polymeric fracturing fluid; polymer specific enzyme breakers, designed to selectively degrade the filter cake; enzyme-polymer complexes that migrate with the polymer; encapsulated enzyme breakers. Breakers using bromine or bromate generating agents specifically designed to degrade the filter cakes formed whilst drilling can also find application in degrading fracturing fluid filter cakes.
The application of many of the disclosed breaker systems can be limited by unfavorable downhole conditions (mainly temperature) and economic factors associated with the methods of protection required to prevent premature viscosity degradation. Moreover, the breaking of conventional polysaccharide polymers and their chemically modified derivatives by means of enzyme, acid or oxidizer breakers can often result in insoluble residues that do not allow optimum fracture conductivity to be achieved.
The water solubility of galactomannans depends on the ratio and distribution of the galactose side chains relative to the mannose backbone. Even though guar gum's mannose to galactose ratio M/G (varying between 1.6 and 1.8) renders it the most water soluble galactomannan, the formation of insoluble residues with higher M/G ratio can arise from the application of non-specific breakers due to the different rate of hydrolysis of side chains and polysaccharide backbone.
Hydroxypropyl guar (HPG), a common chemically modified derivative of guar with improved thermally stability and lower insoluble impurities, was proposed as a potential alternative to minimize damage caused by guar fluids. However, further studies have demonstrated that cross-linked guar and HPG fluids cause approximately the same degree of damage to the formation.
An important aspect of viscosifying agents is the effect of polymer conformation and molecular weight on viscosity. The ability of a polymer to viscosify a dilute solution is normally, evaluated by measuring its intrinsic viscosity, [η]. The relationship between molecular weight, M, and intrinsic viscosity, [η], can be described by the Mark-Houwink-Sakurada equation, [η]=K Ma, where the exponent a gives an indication of how close the polymer conformation in solution is to that of a pure random coil.
For randomly coiled polymers the intrinsic viscosity varies with the polymer coil dimensions (volume <Rg2>3/2 and molecular weight M) according to the well known Flory-Fox equation,
([η]=φ<Rg2>3/2 /M), where φ is a constant. Combining the Mark-Houwink-Sakurada and Flory-Fox equations one can predict the change of the radius of gyration <Rg2>1/2 with molecular weight.
It is commonly accepted that the rheological behaviour of polysaccharides and their hydrophilic or slightly hydrophobic modifications follows a master curve when plotted as log η versus log c*[η] where η is the viscosity and [η] is the intrinsic viscosity and c*[η] being defined as the dimensionless coil overlap parameter. This plot can be approximated by two straight lines with a slope close to 1.4 at low concentrations and close to 5.0 at high concentrations. The two straight lines cross at a given point defining [η]*C* where C* is the overlap concentration. The change in slope defines a transition between the dilute concentration regime where the polymer molecules do not interact with each other, and the semi-dilute regime where the molecules interact with each other and entangle resulting in higher viscosity. The overlap concentration C* is close to the lowest polymer concentration which can be cross-linked to form a space filling gel.
An inverse proportionality rule between C* and [η] has been reported (C*=C′/[η], where C′ is in the range 3.4 to 4 for random coiled polymers. This links the minimum concentration required to form a space filling cross-linked gel (C*) with the molecular weight of the polymer through a universal constant C′ and the Mark-Houwink-Sakurada equation [η]=KMa where K and a depend on polymer-solvent interactions, pressure and temperature.
In a cross-linked polymer gel, the viscosity and gel strength are mainly controlled by a combination of polymer concentration, intrinsic viscosity and cross-link density. High molecular weight polymers can form adequate fracturing viscosities at lower concentrations than their low molecular weight counterparts. The use of high molecular weight polymers reduces C* and therefore the minimum polymer loading required to form a space-filling gel. On the other hand, such high molecular weight polymers require very efficient breakers to reduce viscosity for optimum fracture clean-up. In contrast, the use of lower molecular weight polymers requires a higher polymer loading for cross-linking but a lower degree of breaking for clean-up.
GB patent application GB-2322865 describes methods for cross-linking polymers below an overlap concentration C* using extended cross-linkers. U.S. Pat. No. 6,017,855 claims to have decreased the C* of a CMG (darboxymethyl guar) and CMHPG (carboxymethyl hydroxypropyl guar) to values as low as 0.06% by weight, resulting in the potential, for cross-linked gels with low polymer loading. U.S. Pat. No. 4,683,068 describes a method to crosslink hydroxypropyl guar of low molecular weight (200-300 KDa).
U.S. Pat. No. 6,488,091 (“the '091 patent”) discloses a method to use borate cross-linked, low molecular weight, depolymerized guar derivatives that do not require the use of internal breakers; a so-called “self cleaning” fluid. This patent claims an improved method to treat formations by preparing an aqueous fracturing fluid by cross-linking a “substantially fully hydrated depolymerized polymer” with a cross-linking agent. In the patent, slightly poorer permeability results are obtained for a treatment using 0.3% of borate cross-linked guar broken with activated sodium chlorite when compared to a treatment without breakers using 1.49 wt % depolymerized polymer. The molecular weight of guar is at least 2000 KDa while the molecular weight of a depolymerized polymer may be about 100 KDa to 250 KDa. In practice, the use of such a low molecular weight polymer may require high loadings (as much as five times more than that for raw guar or HPG) to obtain a space-filling cross-linked gel.
U.S. Pat. No. 6,579,947 discloses a low molecular weight, low damaging hydraulic fracturing fluid aimed at high temperature formations, comprising a purely synthetic pre-polymer copolymer containing one water soluble pre-polymer and one hydrophobic pre-polymer. However, no descriptions of the cleaning procedures, the required agents nor the retained permeability levels are disclosed.
Degradable and biodegradable polymers have been extensively proposed to replace less environmentally friendly polymers for several applications ranging from fibers, films, injection molding, extrusion or below molding thermoplastics, to medical stitches or biocompatible implants. The most commonly used and commercially successful degradable polymers found in the literature contain at least one of the following groups or polymers: ester, acetal, sulfide, peptide, amide, polyhydroxy acids, polyesters, polylactones, polyvinyl alcohol, polypeptides, polyester amides, polysaccharides or polysulfides.
U.S. Patent Application No. 2001/0016562 and U.S. Pat. No. 6,162,766 disclose the use of a degradable polymer as a coating to encapsulate breakers for use in fracturing applications. WO patent 00/49272 describes the use of a degradable polymer in the form of fibres as a proppant or proppant support additive aiming to increase the gel strength (storage modulus) of a fracturing fluid by means of a pure buoyancy mechanism. U.S. Pat. No. 6,599,863 describes the use of a polymeric breaker in the form of fibers and/or platelets in a fracturing formulation. U.S. Pat. No. 5,330,005 describes the use of such organic fibers as stabilizing agents to eliminate proppant or formation fines flowback. U.S. Pat. No. 4,848,467 describes the use of a degradable thermoplastic polymeric fiber as a fluid loss additive.
U.S. Patent Application No. 2003/0060374 describes the use of a thermoplastic degradable polymer to improve conventional hydraulic fracturing and sand control processes for very small fractures. This process requires at least 50 wt % of the composition to be the thermoplastic degradable polymer. U.S. Pat. No. 6,277,792 discloses a method to compatibilize chitosan in aqueous acidic solutions by means of its functionalization with a polysaccharide. U.S. Pat. No. 6,358,559 discloses a drilling fluid comprising an alkaline aqueous liquid, chitosan, an anhydride and, optionally, an aldehyde. U.S. Pat. No. 6,291,404 discloses a drilling fluid comprising an alkaline aqueous fluid, chitosan, an amine reactive acid and an aldehyde. U.S. Pat. No. 6,258,755 discloses a method to produce pseudoplastic fluids useful as drilling fluids, completion fluids or filter cake removing fluids by solubilizing chitosan at pH above 7 by incorporating into the fluid aldoses or oligosaccharides. U.S. Patent Applications Nos. 2002/0098987 and 2003/0153467 disclose a diacid anhydride modification of chitosan to be used as drilling fluid.
Methods to synthesize such degradable polymers have been disclosed. A typical method consists of the melt polymerization of the corresponding monomers. U.S. Pat. No. 5,310,865 discloses such a process to produce a thermoplastic polyhydroxyester. Other methods to synthesize biocompatible polymers involve grafting polymers (degradable or not) onto polysaccharide backbones. A process to produce such a polymer involves the use of ceric ion salts (e.g. ammonium cerium (IV) nitrate) to selectively oxidize the polysaccharide backbone at the carbons of the cis-hydroxy groups available in several polysaccharide types. Polymers produced by this method have found application in the oilfield as fluid loss additives.
In summary, most of the existing fracturing fluids rely on the use of conventional breaker technologies which can result in inefficient clean-up. The use of alternative technologies that do not require aggressive breakers, such as fracturing fluids comprising depolymerized polysaccharides, results in very high polymer loadings that are less cost effective. The use of commercially available degradable polymers such as polylactones or polyhydroxyesters encounters two major problems; the lack of water solubility and their high cost compared to typical raw polysaccharides or their chemically modified derivatives. Despite prior efforts undertaken by several researchers to produce alternative solutions to the damage problem, there is still a need to develop new polymer based fracturing fluids that can form gels at low concentrations and whose degradation creates a low viscosity non-damaging fluid due to processes which are less sensitive to breaker type, diffusion and reservoir conditions, and incorporating processes which can be carried out in a controlled way.